Vermilion Energy Inc.
Q3 2017 Earnings Call Transcript

Published: 30 Oct 2017

[Operator:]

Good morning. My name is Jody and I will be your conference operator today. At this time, I would like to welcome everyone to the Vermilion Energy Incorporated Third Quarter Results Conference Call. All lines have been placed on mute to prevent any background noise. After the speakers’ remarks, there will be a question-and-answer session. [Operator Instructions] Thank you. Mr. Anthony Marino, President and CEO, you may begin your conference.

[Anthony Marino:]

Good morning, ladies and gentlemen. Thank you for joining us. I am Tony Marino, President and CEO of Vermilion Energy. With me today are Mike Kaluza, Executive Vice President and COO; Curtis Hicks, Executive Vice President and CFO; and Kyle Preston, our Director of Investor Relations. I would first like to refer to the advisory on forward-looking statements contained in today’s news release. These advisories describe the forward-looking information, non-GAAP measures, and oil and gas terms referred to today and outline the risk factors and assumptions relevant to this discussion. During this call, I’ll provide you with an overview of our third quarter 2017 financial and operating results and our 2018 budget and guidance, which was announced with our Q3 results this morning. Third quarter production was approximately 67,400 boe/d, an increase of about 200 boe/d from Q2. Production was negatively affected by downtime at Corrib, which reduced Q3 production by approximately 2400 boe/d. Higher production in Canada and the US was achieved through successful drilling programs in the first nine months of the year, while Netherlands production benefited from receipt of permits and reduced turnaround work. FFO for Q3 was $131 million or $1.08 per share which was down approximately 11% quarter-over-quarter primarily due to the unplanned downtime in Ireland and lower realized commodity prices. The downtime at Corrib had an estimated FFO impact of approximately $8.5 million or $0.07 per share in Q3. Despite this quarterly decrease in FFO, our payout ratio for the first nine months of 2017 was 94%. Q3 operations review, with respect to operations let's start with Europe. In Q3, we drilled two gross 1.0 net wells in the Netherlands. The Eesveen-02 60% working interest encountered 24 meters of net pay in two separate intervals targeting Zechstein 2 carbonate and the Rotliegend sandstone. The second well, Nieuwehorne-02, 42% working interest, also targeted two separate intervals, the Zechstein 2 carbonate and the Vlieland sandstone encountering ten meters of net pay. The two zones in the Eesveen-02 well tested at a combined rate in excess of 18 million cubic feet per day net. This well is expected to be brought on production in mid-208. Test results for the Nieuwehorne-02 well will be available by the time of our year-end release. As announced with our Q2 results in July, the Ministry of Economic Affairs approved a production rate increase on one of our pools which became effective in early September. As a result, production in the Netherlands is currently back up over 8,000 boe/d and should continue to grow through the balance of the year. We also receive additional permits for 3D seismic survey in the Akkrum and South Friesland III exploration licenses, and have increased the size of the program from 220 square kilometers to 315 square kilometers, with completion of the program expected prior to the end of the year. In Ireland, production from Corrib averaged 49 million cubic feet a day or 8,200 boe/d in Q3, a 23% reduction from Q2 due to an downtime following a plant turnaround as I mentioned earlier. Although turnaround tasks were completed successfully, unodorized gas was detected in the gas distribution network following plant restart. This resulted in an extended period of downtime to remove the unodorized gas and to implement process changes to ensure that odorant would be continuously injected and monitored in future plant operation. Production at Corrib resumed on October 11th after 21 days of downtime in Q3 and ten days of downtime in Q4. The annualized impact from this downtime, net to Vermilion, is estimated at approximately 900 boe/d. we are progressing toward closing of our acquisition of additional interest in Corrib currently scheduled for mid-2018 and we look forward to Vermilion operatorship of the project at that time. In Germany, we continue to execute workover and artificial lift optimization operations on the assets we acquired in December 2016. For the second consecutive quarter, production from the acquired assets was 10% above pre-acquisition levels and contributed to a modest increase in overall business unit production from Q2 despite no new drilling activity. Compared to Q3 2016, production has increased by 82% through our acquisition and organic growth activities, and has contributed to a much stronger free cash flow profile for the German Business Unit. Based on current strip pricing, we are forecasting the German business to deliver free cash flow of approximately 65% in 2017. In Canada, we continue to successful execute our 2017 capital program. During Q3, we drilled or participated in ten 8.0 net Mannville wells, two 2.0 net Cardium wells and three 2.8 net Midale wells. We brought on production seven 5.6 net Mannville wells, two 2.0 net Cardium wells and three 2.8 net Midale wells. All three projects continue to deliver predicable results, driving a 29% increase in year-over-year quarterly production to approximately 31,500 boe/d for the Canadian Business Unit. As most of you are probably aware, there were significant third-party maintenance by TCPL in west-central Alberta in the third quarter, with planned and unplanned disruptions restricting available capacity on multiple gathering systems. Despite these restrictions, our Canadian Business Unit was able to deliver on its growth targets. In United States, production grew 16% quarter-over-quarter as a result of three 3.0 net Turner Sand wells drilled in the first quarter setting the stage for an increased drilling program in 2018. Our 25,500 acre Rex Federal Unit in the northern part of the Turner Sand project was approved by the Bureau of Land Management in early October. In addition, we received a paying well determination from the BLM for the 24,400 acre Three Horn Federal Unit in the southern part of the project. This determination eliminates a 180-day continuous drilling obligation and holds the leases within the Three Horn Unit for a minimum of five years. These federal units cover the majority of our Turner Sand project, giving us an even lower expiry profile and greater control over the pace and focus of development activities. 2017 production guidance. Achieving our guidance targets is very important to us. Early in 2017, we encountered unexpected permitting difficulties in the Netherlands, and accordingly constructed and implemented a revised investment and production plan that called on other jurisdictions to make up this difference. While the revised plan was successful in generating the expected production volumes in our operated business units, we experienced downtime at our Corrib project, which is currently outside operated in September. At this point in the year, this foregone production is impossible to make up from other sources during 2017. As a result, we have reduced our 2017 production guidance by 1000 boe/d to a range of 68,000 to 69,000 boe/d. Nonetheless, we still expect to achieve 2017 year-over-year production growth of approximately 8% in absolute terms, and approximately 3% on a per-share basis. Government policy developments. I would now like to touch on recent policy developments in France following up on our comments in the Q2 conference call. In early September, the French government announced further details on its proposed Climate Plan, and enabling legislation is currently being debated in the French Parliament. The plan contains a number of elements broadly affecting the French economy, including reductions in nuclear power generation and future restrictions on internal combustion engines and hydrocarbon-based fuels for cars. Two previously-announced elements affect the French E&P industry. First, the legislation prohibits the issuance of new exploration concessions in France, although existing exploration concessions may be converted to production concessions in the event of hydrocarbon discoveries. Vermilion is largely unaffected by this change. Our French investment activities are overwhelmingly concentrated in development projects on existing fields in existing production concessions. In a limited set of existing exploration concessions, we do intend to conduct seismic and drilling operations, and in these cases, the proposed legislation allows conversion to production concessions if exploration is successful. Second, the legislation puts a limit on renewals of existing production concessions at the year 2040. As with the prohibition on issuance of new exploration concessions, we expect an immaterial effect on Vermilion's production and reserve profile from this proposal. Speaking more broadly, operating in Europe has always been more challenging as compared to North America, but we have demonstrated throughout our history that the superior return we achieve from our European assets is well worth the additional effort. We have a long track record of profitably increasing our oil and gas production in Europe and we have the appropriate personnel and business practices in place to continue to succeed in this exacting but high return jurisdiction. The operating and business development franchise that we have established in Europe would be difficult to replicate and should provide us with a significant competitive advantage in the future. Our European franchise and skill set may in fact become more valuable over time as other companies may elect to exit this demanding region, potentially creating a greater pace of business development opportunity. In the nearer term, we look very much forward to continuing our contributions to the French economy, resuming growth in the Netherlands, beginning drilling in Central and Eastern Europe, and assuming operatorship of our Corrib project in Ireland. It is our firm belief that our growing share of the European E&P business is desirable for the governments and citizens of these jurisdictions as well as for Vermilion. Vermilion is a leader in sustainability. We were designated as a Climate A list company by CDP, formerly the Carbon Disclosure Project in 2016, one of only five energy companies in the world to receive this designation. In addition, we have several ongoing sustainability projects in Europe that reduce carbon emissions while simultaneously promoting new industries and economic inclusivity, and we intend to implement more sustainability projects over time. While we support and are a part of the long-term energy transition, we believe that the transition is best realized by turning to best in class companies such as Vermilion to produce the oil and gas that will be consumed in the European and world economies during the coming decades. 2018 budget, lastly in conjunction with our Q3 results, we announced our formal 2018 budget and have affirmed our long-term targets of delivering 5% to 7% production per share growth at a payout ratio of less than 100%. Our Board of Directors has formally approved an exploration and development capital budget of $315 million for 2018, with associated production guidance of 74,500 to 76,500 boe/d. The midpoint of our formal 2018 production guidance is unchanged as compared to our preliminary target that we previously announced and our combined E&D capital guidance for 2017 and 2018 is slightly below previous targets. Production growth for 2018 is projected to be 11% of an absolute basis results and 8% on a per share basis. For the two-year period for 2017 to this results compound annual growth of 9% with a forecasted payout ratio of below 100% in both years based on current strip pricing. This budget funds development of a number of high return projects, including investment in our three main projects in Canada, continued development in both the Neocomian and Champotran fields in France, a return to production growth in the Netherlands where we continue to benefit from favorably priced European natural gas, continued development of our Turner Sands play in the United States, and inaugural drilling in our Central and Eastern Europe business unit. More detailed summary of our 2018 capital program please refer to our Q3 release or our November 2017 investor presentation available on our website. That concludes my planned remarks, we would be happy to address any questions that you might have. Operator would you please open the phone lines to questions?

[Operator:]

[Operator Instructions] Your first question comes from the line of Greg Pardy of RBC Capital Markets. Your line is open.

[Greg Pardy:]

I've got three quick ones for you Tony. The first one is just with the lower - with the – just Western Canada, you referred to the Mannville, are all of those wells lower Mannville and then can you just comment on what the liquids and condensate cuts would be roughly.

[Anthony Marino:]

For the Mannville question, are you referring to the drilling that we did in Q3?

[Greg Pardy:]

Yes.

[Anthony Marino:]

In the Q3 drilling, in fact in the entire year program and for next years, the vast majority of that is in the lower Mannville or the Ellerslie. I think we have - I think for this year’s program as a whole we have two or three wells in the upper Mannville and that’s the same plan that we have for next year. Typically just drilling expiries in the upper Mannville which is not as liquids and condensate rich as is the lower Mannville or Ellerslie. For the yields, we typically are - I’m just going to refer to our investor deck for a second to quote these for you, in the Ellerslie our overall yield is a little bit over 100 barrels per million of hydrocarbon liquids per million cubic of the sales gas. And of that 100 barrels a million, two thirds of it is condensate, the remainder is NGLs.

[Greg Pardy:]

And then just for the 2018 program, could you give us a set up in terms of what the plan is for both the Turner Sands and then just for Germany?

[Anthony Marino:]

Mike, would you like to address that for starting with - starting with US and then Germany?

[Mike Kaluza:]

In the US and the Turner Sands program we're going to be drilling a total of five wells. Four of those wells are on two well per pad locations down in the southern end of our lands and the fifth well will be up in the new federal unit that we just formed as a well to stabilize that unit. In Germany basically what we're going to be doing there is preparing for the 2019 program, getting ready for the Burgmoor Z5. That will be our first operated well in the Dümmersee-Uchte. We do have another well that [indiscernible] well, a non-operated drill that we’re just doing preparatory work on that one. So in Germany, it's mostly just getting ready for the ’19 drilling program.

[Operator:]

Your next question comes from the line of Nima Billou of Veritas Investment Research. Your line is open. Nima, your line is open. [Operator Instructions] Your next question comes from the line of Darren Engels with GMP.

[Darren Engels:]

Could you tell me what the ramp up looks like in production in the Netherlands for 2018?

[Anthony Marino:]

Yes, Darren. Give us just a second. Thank you for the question and we’ll refer to that production plan for next year. So we will be ramping up Q1 through Q3 and declining slightly in Q4 in the production plan that we have. For an overall production level for the year, that is a little bit in excess of 10,000 boe/d.

[Operator:]

You next question comes from the line of Nima Billou of Veritas Investment Research.

[Nima Billou:]

Just wanted to talk about a couple of different strategic issues. With respect to the international operations, you guys have always been adept at handling the regulatory environment, but you mentioned permitting issues in the Netherlands for French production, it looks like growth will likely be off the table. Where is there a reshuffling in order to I guess go to areas where those challenges aren't as longstanding or sort of volume inhibiting, like, what are the countries internationally next that are going to receive some of that capital, that attention that are going to be going away potentially from France.

[Anthony Marino:]

Let's start off with the specifics of the French and the Netherlands units and then we'll go more generally to Europe. So for France actually, the unit’s production profile I don't think is going to change as a result of the new climate plan. We're going to continue to invest at a moderate level in France as we have previously. I think it will be a low single digit grower over time. I think that can continue actually for quite a long period and during that time, it'll be generating quite a bit of free cash flow as it has in the past. So really no change at all in the way that we're going to be managing France. It’s really quite a long term program that the French government has put in place. It's mainly going to come out of our development activities. But we will be conducting some seismic and ultimately drilling on an exploration license in Alsace-Lorraine. So, I think there's actually quite a diversity of -- quite a diverse set of projects that will lead this French production profile to continue as we have managed it previously. In the Netherlands, we are resuming growth in 2018. We had actually recorded seven straight years of growth, prior to 2017 and we were quite proud of that record. It's been a very strong unit for us. We had program to be up in ’17, but due to some of the permitting setbacks that we experienced, we're actually going to be down a little bit this year, but resumed growth along the same profile that we had previously expected in ’18. I think we have a very bright future there as well. And I see it as a long-term moderate growth unit, again one that will generate a lot of free cash. Those businesses really in terms of the production profile I don't think have changed. As I said in the prepared remarks earlier, Europe has always been a challenge to permit in. The difficulty and the number of hurdles you have to go through sometimes vary. We had greater hurdles earlier this year in the Netherlands. I think our permit profile has already improved there. I don't expect permitting to get easier in these jurisdictions or in Europe in general. But in fact this is a big competitive advantage we have, it's a very high return business and one that other companies haven't been willing to go into or never established the operating base that we did over the past 20 years. And I think for new competitors it's pretty unlikely that they would come in now given that the already difficult permitting hasn't gotten any easier. And in fact we face a little bit more difficult profile probably going forward. So we're used to this environment. We've established the expertise, the relationships, the operating record with governments, the operating record that other companies who might be selling assets want to see. And as a result I actually think that this is going to end up enhancing our competitive advantage and probably in terms of M&A opportunities give us a little bit better profile going forward. Now there's no particular transaction we can put our finger on at this point. The deal flow has always been pretty slow, there are pretty intermittent, but if anything it would perhaps be greater in the future and we have tended to make quite high rate of return acquisitions there. I expect our organic growth profile to continue in Germany both on the assets that we acquired from Engie and in the Exxon Farm-In that gives us actually about a quarter of the net lands in the Lower Saxony Basin or North German basin that make up the vast, vast majority of German production. We've got the data that you need to be successful there, we've got the access to infrastructure. I think a lot of good prospects on the Farm-In. And as a result I think we're going to have a positive organic profile in Germany with always the potential for further acquisitions. In Central and Eastern Europe, I think we've established a great land base in some countries that other companies I think have overlooked in the past. We are the Number One oil and gas mineral landholder in Croatia. We've got I think a very high quality position in Slovakia for shallow gas. And we have the Hungarian licenses that we put in place a few years ago, we're going to start drilling in 2018. So actually I think in each of these onshore business units in Europe, we've already set the stage for continuing growth. And if anything coming back to the original point behind your question, I think that the permitting challenges will make it more possible - even more possible for us to achieve that growth profile going forward.

[Nima Billou:]

I appreciate your very thoughtful answers, just that I, you know, that's something that needs to be communicated and reinforced because people see the headline on those government initiatives and they think that it permanently impairs your businesses and given your operational track record that may be one of the reasons it's sort of holding back the share price. My final question is on the Mannville side, clearly you’re putting more attention on the Canadian opportunities set, I think intelligently so you guys have always gotten good acreage, you see a good opportunity on this liquids rich side. And I'm going through your presentation and I see that certain wells are good even with a zero AECO price, but AECO weakness can’t really be ignored right now. The 12-month strip is at 2.16 and your economics begin at 2.50. Do you still see the same attention and same levels of capital expenditures, given a weak AECO price or is it flexible that you can adjust downward, if need be, because these liquids rich opportunities, when you still see the production profile are 60%, 70% gas when I look at your bar charts and that gas price has to inherently affect the economics of that well. So I just want to see or are there any things that you can do to mitigate AECO weakness. There are some producers selling directly into Chicago. So I just wanted to get your take on facing that wall of low AECO pricing and how it may change your outlook with respect to the near term inherently on your Canadian opportunity set?

[Anthony Marino:]

For sure. So let's take those questions piece by piece. The first thing is there flexibility in the Canadian program. Well, absolutely. I mean that's the beauty of the North American business and particularly in Canada where most of this permitting is routine. It is quite easy to ramp up and down the program in response to prices. The next part of it about the about the returns on the projects, these wells that we're drilling, with the exception of just a couple of expiries in the Notikewin or Fahler. These wells that we're drilling on the Ellerslie actually have very little dependence on AECO. Of course, it’s better to have a higher gas price than a lower one, but even though one third of the production mix is liquids, primarily condensate for us, the economics are still carried by that conde. The wells are just so productive at pretty low cost and continue to come down that you can achieve extremely high rates of return even with low or zero gas prices and this is illustrated in the investor deck where we point out that even if we have no AECO price and we have $50 WTI, we would still make a 31% return on that Mannville program. So, certainly we’ll accept the higher gas price, but -- if it occurs, but we are drilling those wells to make the liquids again with the exception of the ones that we drill for expiry just to hold those lands in the Ferrier area. Now addressing the dynamics of the gas market, it's true these AECO prices were very, very weak, particularly in September and I think everybody's aware of the causes of this increasing flows on to the system, at the same time that there's been a lot of downtime for pre-planned maintenance by TCPL. Prices have begun to recover in October and of course the forward curve is better, especially during the winter when there's more seasonal demand for gas. All that said, the long term AECO basis is still well above a dollar deduction to NYMEX and I would find it hard to make a case that it's going to get too much flow of that. I'll point out that we're 80% hedged in Q4 for our Alberta gas. And again we're conducting this business to produce the condensate into a lesser extent the NGLs because that is really what drives the economics.

[Operator:]

[Operator Instructions] There are no further questions in the queue at this time. I’ll turn the call back over to Mr. Marino for final remarks.

[Anthony Marino:]

Thank you again for participating in our conference call. We look forward to speaking with you again after our annual release in March 2018.

[Operator:]

This concludes today's conference call. You may now disconnect.